1. Field of the Invention
Embodiments of the present invention generally relate to techniques for processing seismic data and, more particularly, to determining an accurate differential transfer function (DTF) between two closely spaced hydrophones in an effort to properly separate the wavefield into up- and down-going components.
2. Description of the Related Art
In the oil and gas industry, seismic surveys are one of the most important techniques for discovering the presence of subterranean hydrocarbon deposits. If the data is properly processed and interpreted, a seismic survey can provide geologists with a two-dimensional (2-D) or three-dimensional (3-D) representation of subsurface lithologic formations and other features, so that they may better identify those formations likely to contain oil and/or gas. Having an accurate representation of an area's subsurface lithologic formations can increase the odds of hitting an economically recoverable reservoir when drilling and decrease the odds of wasting money and effort on a nonproductive well.
A seismic survey is conducted by deploying an array of energy sources and an array of receivers in an area of interest. Typically, vibrator trucks are used as sources for land surveys, and air guns are used for marine surveys. The sources are discharged in a predetermined sequence, sending a down-going seismic wavefield or signal into the earth that is partially reflected by subsurface seismic reflectors (i.e., interfaces between subsurface lithologic or fluid units having different elastic properties). The reflected or up-going wavefield or signals (known as “seismic reflections”) are then detected and converted to electrical signals by the array of receivers located at or near the surface of the earth, at or near the water surface, or at or near the seafloor.
Each receiver records the amplitude of the incoming signals over time at the receiver's particular location, thereby generating a seismic survey of the subsurface. The seismic energy recorded by each seismic receiver for each source activation during data acquisition is generally referred to as a “trace.” Since the physical location of the sources and receivers is known, the time it takes for a reflection wave to travel from a source to a sensor is directly related to the depth of the formation that caused the reflection. Thus, the recorded signals, or seismic energy data, from the array of receivers can be analyzed to yield valuable information about the depth and arrangement of the subsurface formations, some of which hopefully contain oil or gas accumulations.
This analysis typically begins by organizing the data from the array of receivers into common geometry gathers, where data from a number of receivers that share a common geometry are analyzed together. A gather will provide information about a particular location or profile in the area being surveyed. Ultimately, the data will be organized into many different gathers and processed before the analysis is completed in an effort to map the entire survey area. The types of gathers typically employed include common midpoint (i.e., the receivers and their respective sources share a common midpoint), common source (i.e., the receivers share a common source), common offset (i.e., the receivers and their respective sources have the same separation or “offset”), and common receiver (i.e., a number of sources share a common receiver).
The data in a gather is typically recorded or first assembled in the time-offset domain. That is, the seismic traces recorded in the gather are assembled or displayed together as a function of offset (i.e., the distance of the receiver from a reference point) and of time. The time required for a given signal to reach and be detected by successive receivers is a function of its velocity and the distance traveled. Those functions are referred to as kinematic travel time trajectories. Thus, at least in theory, when the gathered data is displayed in the time-offset domain (the T-X domain), the amplitude peaks corresponding to reflection signals detected at the receivers should align into patterns that mirror the kinematic travel time trajectories. It is from those trajectories that one ultimately may determine an estimate of the depths at which formations exist.
The seismic receivers utilized in such operations typically include pressure sensors, such as hydrophones, and velocity sensors, such as single or multi-component geophones. The combination of a hydrophone and a vertical geophone to form a dual-sensor has long been used as a technique for attenuating ghost reflections from the air-water interface. The fundamental concept is that up-going and down-going waves are measured differently by a velocity sensor, while direction of progression of the wave has no polarity significance to the hydrophone. However, in some situations the geophone signals from dual-sensor recording are quite noisy due to interface waves in the muddy water bottom. In such cases, the use of pairs of vertically separated hydrophones (dual-hydrophone setups) deployed some meters above the water bottom would present clear advantages in ocean bottom operations. In streamer operation, use of dual-hydrophones would enable the elimination of the receiver ghost from the surface. Therefore, dual-hydrophone cables could be towed at a much larger depth, which widens the operational window considerably and enables the capture of lower frequencies.
Such a pair of vertically separated hydrophones disposed in a water layer can be used to separate the wavefield into up- and down-going components. The information needed to perform the separation is encoded into the difference signal between the two hydrophones, and the established practice is to have a separation distance of at least several meters. However, the use of closely spaced dual-hydrophones with a vertical separation distance of 1 m or less has obvious operational advantages over setups with several meters of vertical separation. For example, the closely spaced hydrophones could be built into a single housing and deployed much more easily than paired hydrophones separated by several meters. However, there are problems associated with processing data from closely spaced dual-hydrophones.
Accordingly, what is needed is an improved method of processing dual-hydrophone data such that meaningful seismic data may be extracted, especially for pairs of closely spaced hydrophones.